Methods for separating oil and/or gas mixtures

ABSTRACT

A method for producing oil, comprising injecting water and a solvent into a formation; producing a mixture comprising water, solvent, oil, and gas from the formation; separating the mixture into a first stream comprising oil, water, and a first portion of the solvent, and a second stream comprising gas and a second portion of the solvent, and exposing the second stream to water to remove the second portion of the solvent from the gas.

This application is a divisional of U.S. Nonprovisional application Ser.No. 13/421,387 filed Mar. 15, 2012 which claims the benefit of U.S.Provisional Application No. 61/454,025, filed Mar. 18, 2011,incorporated herein by reference.

FIELD OF THE INVENTION

The present disclosure relates to methods for producing oil and/or gasmixtures, then separating the mixtures.

BACKGROUND OF THE INVENTION

Enhanced Oil Recovery (EOR) may be used to increase oil recovery infields worldwide. There are three main types of EOR, thermal,chemical/polymer and gas injection, which may be used to increase oilrecovery from a reservoir, beyond what can be achieved by conventionalmeans—possibly extending the life of a field and boosting the oilrecovery factor.

Thermal enhanced recovery works by adding heat to the reservoir. Themost widely practiced form is a steam drive, which reduces oil viscosityso that it can flow to the producing wells. Chemical flooding increasesrecovery by reducing the capillary forces that trap residual oil.Polymer flooding improves the sweep efficiency of injected water.Miscible injection works in a similar way as chemical flooding. Byinjecting a fluid that is miscible with the oil, trapped residual oilcan be recovered.

Referring to FIG. 1, there is illustrated prior art system 100. System100 includes underground formation 102, underground formation 104,underground formation 106, and underground formation 108. Productionfacility 110 is provided at the surface. Well 112 traverses formations102 and 104, and terminates in formation 106. The portion of formation106 is shown at 114. Oil and gas are produced from formation 106 throughwell 112, to production facility 110. Gas and liquid are separated fromeach other, gas is stored in gas storage 116 and liquid is stored inliquid storage 118.

U.S. Pat. No. 2,859,818 discloses a method for recovering petroleum froma formation by injecting a solvent. The solvent may be a hydrocarbonsolvent such as alcohols, gasoline, kerosene, dimethyl ether, otherhydrocarbons having from 2 to 5 carbon atoms, or mixtures. U.S. Pat. No.2,859,818 is herein incorporated by reference in its entirety.

U.S. Pat. No. 2,910,123 discloses a method for recovering petroleum froma formation by injecting a solvent. The solvent may be a hydrocarbonsolvent such as alcohols, gasoline, kerosene, dimethyl ether, otherhydrocarbons having from 2 to 5 carbon atoms, or mixtures. PCT PatentApplication Publication WO 2010/02693 discloses a method comprisingrecovering a carbon source from a formation; converting at least aportion of the carbon source to a synthesis gas; converting at least aportion of the synthesis gas to an ether; and injecting at least aportion of the ether into the formation.

PCT Patent Application Publication WO 2008/141051 discloses a system forproducing oil and/or gas from an underground formation including a wellabove the formation; a mechanism to inject an enhanced oil recoveryformulation into the formation, the enhanced oil recovery formulationincluding dimethyl ether; and a mechanism to produce oil and/or gas fromthe formation.

PCT Patent Application Publication WO2011/140180 discloses a system forproducing oil and/or gas from an underground formation comprising a wellabove the formation; a mechanism to inject an enhanced oil recoveryformulation into the formation, the enhanced oil recovery formulationcomprising water and an additive; and a mechanism to produce oil and/orgas from the formation.

There is a need in the art for improved systems and methods for enhancedoil recovery. There is a further need in the art for improved systemsand methods for enhanced oil recovery using a solvent enhanced waterflood. There is a further need in the art for improved systems andmethods for improving the recovery and recycling of a solvent from a EORflooding operation.

SUMMARY OF THE INVENTION

In one aspect, the invention provides a method for producing oil,comprising injecting water and a solvent into a formation; producing amixture comprising water, solvent, oil, and gas from the formation;separating the mixture into a first stream comprising oil, water, and afirst portion of the solvent, and a second stream comprising gas and asecond portion of the solvent, and exposing the second stream to waterto remove the second portion of the solvent from the gas.

Advantages of the invention include one or more of the following:

Improved methods for recovery of an enhanced oil recovery solvent.

Improved methods for recycling of an enhanced oil recovery solvent.

Improved methods for enhanced recovery of hydrocarbons from a formationwith a solvent enhanced water flood.

Improved methods for enhanced recovery of hydrocarbons from a formationwith a water injectant containing an oil soluble or miscible additive.

Improved compositions and/or techniques for secondary recovery ofhydrocarbons.

Improved methods for enhanced oil recovery.

Improved methods for enhanced oil recovery using a miscible additive ina water flood.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a prior art oil and gas production system.

FIG. 2 a illustrates a well pattern.

FIGS. 2 b and 2 c illustrate the well pattern of FIG. 2 a duringenhanced oil recovery processes.

FIGS. 3 a-3 c illustrate oil and gas production systems.

FIG. 4 illustrates a separation system.

DETAILED DESCRIPTION OF THE INVENTION

FIGS. 2 a, 2 b, & 2 c:

Referring now to FIG. 2 a, in some embodiments, an array of wells 200 isillustrated. Array 200 includes well group 202 (denoted by horizontallines) and well group 204 (denoted by diagonal lines).

Each well in well group 202 has horizontal distance 230 from theadjacent well in well group 202. Each well in well group 202 hasvertical distance 232 from the adjacent well in well group 202.

Each well in well group 204 has horizontal distance 236 from theadjacent well in well group 204. Each well in well group 204 hasvertical distance 238 from the adjacent well in well group 204.

Each well in well group 202 is distance 234 from the adjacent wells inwell group 204. Each well in well group 204 is distance 234 from theadjacent wells in well group 202.

In some embodiments, each well in well group 202 is surrounded by fourwells in well group 204. In some embodiments, each well in well group204 is surrounded by four wells in well group 202.

In some embodiments, horizontal distance 230 is from about 5 to about1000 meters, or from about 10 to about 500 meters, or from about 20 toabout 250 meters, or from about 30 to about 200 meters, or from about 50to about 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, vertical distance 232 is from about 5 to about 1000meters, or from about 10 to about 500 meters, or from about 20 to about250 meters, or from about 30 to about 200 meters, or from about 50 toabout 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, horizontal distance 236 is from about 5 to about1000 meters, or from about 10 to about 500 meters, or from about 20 toabout 250 meters, or from about 30 to about 200 meters, or from about 50to about 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, vertical distance 238 is from about 5 to about 1000meters, or from about 10 to about 500 meters, or from about 20 to about250 meters, or from about 30 to about 200 meters, or from about 50 toabout 150 meters, or from about 90 to about 120 meters, or about 100meters.

In some embodiments, distance 234 is from about 5 to about 1000 meters,or from about 10 to about 500 meters, or from about 20 to about 250meters, or from about 30 to about 200 meters, or from about 50 to about150 meters, or from about 90 to about 120 meters, or about 100 meters.

In some embodiments, array of wells 200 may have from about 10 to about1000 wells, for example from about 5 to about 500 wells in well group202, and from about 5 to about 500 wells in well group 204.

In some embodiments, array of wells 200 is seen as a top view with wellgroup 202 and well group 204 being vertical wells spaced on a piece ofland. In some embodiments, array of wells 200 is seen as across-sectional side view with well group 202 and well group 204 beinghorizontal wells spaced within a formation.

Referring now to FIG. 2 b, in some embodiments, array of wells 200 isillustrated. Array 200 includes well group 202 (denoted by horizontallines) and well group 204 (denoted by diagonal lines).

In some embodiments, a water flooding mixture is injected into wellgroup 204, and oil and gas are recovered from well group 202. Asillustrated, the water flooding mixture has injection profile 208, andoil and gas recovery profile 206 is being produced to well group 202.

In some embodiments, a water flooding mixture is injected into wellgroup 202, and oil and gas are recovered from well group 204. Asillustrated, the water flooding mixture has injection profile 206, andoil and gas recovery profile 208 is being produced to well group 204.

In some embodiments, well group 202 may be used for injecting a waterflooding mixture, and well group 204 may be used for producing oil andgas from the formation for a first time period; then well group 204 maybe used for injecting a water flooding mixture, and well group 202 maybe used for producing oil and gas from the formation for a second timeperiod, where the first and second time periods comprise a cycle.

In some embodiments, multiple cycles may be conducted which includealternating well groups 202 and 204 between injecting a water floodingmixture, and producing oil and gas from the formation, where one wellgroup is injecting and the other is producing for a first time period,and then they are switched for a second time period.

In some embodiments, a cycle may be from about 12 hours to about 1 year,or from about 3 days to about 6 months, or from about 5 days to about 3months. In some embodiments, each cycle may increase in time, forexample each cycle may be from about 5% to about 10% longer than theprevious cycle, for example about 8% longer. In some embodiments, awater flooding mixture may be injected at the beginning of a cycle, andan immiscible enhanced oil recovery agent or a mixture including animmiscible enhanced oil recovery agent may be injected at the end of thecycle. In some embodiments, the beginning of a cycle may be the first10% to about 80% of a cycle, or the first 20% to about 60% of a cycle,the first 25% to about 40% of a cycle, and the end may be the remainderof the cycle.

Referring now to FIG. 2 c, in some embodiments, array of wells 200 isillustrated. Array 200 includes well group 202 (denoted by horizontallines) and well group 204 (denoted by diagonal lines).

In some embodiments, a water flooding mixture is injected into wellgroup 204, and oil and gas are recovered from well group 202. Asillustrated, the water flooding mixture has injection profile 208 withoverlap 210 with oil and gas recovery profile 206, which is beingproduced to well group 202.

In some embodiments, a water flooding mixture is injected into wellgroup 202, and oil and gas are recovered from well group 204. Asillustrated, the water flooding mixture has injection profile 206 withoverlap 210 with oil and gas recovery profile 208, which is beingproduced to well group 204.

Enhanced Oil Recovery Methods

The recovery of oil and gas with array of wells 200 from an undergroundformation may be accomplished by any known method. Suitable methodsinclude subsea production, surface production, primary, secondary, ortertiary production. The selection of the method used to recover the oiland gas from the underground formation is not critical.

In some embodiments, oil and gas may be recovered from a formation intoa well, and flow through the well and flowline to a facility. In someembodiments, enhanced oil recovery, water with the use of an added agentfor example a surfactant, a polymer, and/or a miscible agent such as adimethyl ether formulation or carbon dioxide, may be used to increasethe flow of oil and gas from the formation.

Releasing at least a portion of the water flooding mixture and/or otherliquids and/or gases may be accomplished by any known method. Onesuitable method is injecting the water flooding mixture into a singleconduit in a single well, allowing the water flooding mixture to soak,and then pumping out at least a portion of the water flooding mixturewith gas and liquids. Another suitable method is injecting the waterflooding mixture into a first well, and pumping out at least a portionof the water flooding mixture with gas and liquids through a secondwell. The selection of the method used to inject at least a portion ofthe water flooding mixture and/or other liquids and/or gases is notcritical.

In some embodiments, the water flooding mixture and/or other liquidsand/or gases may be pumped into a formation at a pressure up to thefracture pressure of the formation.

In some embodiments, the water flooding mixture may be mixed in with oiland/or gas in a formation to form a mixture which may be recovered froma well. In some embodiments, a quantity of the water flooding mixturemay be injected into a well, followed by another component to force theformulation across the formation. For example air, water in liquid orvapor form, carbon dioxide, other gases, other liquids, and/or mixturesthereof may be used to force the water flooding mixture across theformation.

FIGS. 3 a & 3 b:

Referring now to FIGS. 3 a and 3 b, in some embodiments of theinvention, system 300 is illustrated. System 300 includes undergroundformation 302, underground formation 304, underground formation 306, andunderground formation 308. Facility 310 is provided at the surface. Well312 traverses formations 302 and 304, and has openings in formation 306.Portions 314 of formation 306 may be optionally fractured and/orperforated. During primary production, oil and gas from formation 306 isproduced into portions 314, into well 312, and travels up to facility310. Facility 310 then separates gas, which is sent to gas processing316, and liquid, which is sent to liquid processing 318. Facility 310also includes water flooding mixture storage 330. As shown in FIG. 3 a,water flooding mixture may be pumped down well 312 that is shown by thedown arrow and pumped into formation 306. Water flooding mixture may beleft to soak in formation for a period of time from about 1 hour toabout 15 days, for example from about 5 to about 50 hours.

After the soaking period, as shown in FIG. 3 b, water flooding mixtureand oil and gas is then produced back up well 312 to facility 310.Facility 310 is adapted to separate and/or recycle water floodingmixture, for example by a gravity separation, centrifugal separation,chemical absorption, and/or by boiling the formulation, condensing it orfiltering or reacting it, then storing or transporting desirable liquidsand gases, and re-injecting and/or disposing of undesirable liquids andgases, for example by repeating the soaking cycle shown in FIGS. 3 a and3 b from about 2 to about 5 times.

In some embodiments, water flooding mixture may be pumped into formation306 below the fracture pressure of the formation, for example from about40% to about 90% of the fracture pressure.

In some embodiments, well 312, as shown in FIG. 3 a, injecting intoformation 306 may be representative of a well in well group 202, andwell 312 as shown in FIG. 3 b, producing from formation 306, may berepresentative of a well in well group 204.

In some embodiments, well 312 as shown in FIG. 3 a, injecting intoformation 306, may be representative of a well in well group 204, andwell 312, as shown in FIG. 3 b, producing from formation 306 may berepresentative of a well in well group 202.

FIG. 3 c:

Referring now to FIG. 3 c, in some embodiments of the invention, system400 is illustrated. System 400 includes underground formation 402,formation 404, formation 406, and formation 408. Production facility 410is provided at the surface. Well 412 traverses formation 402 and 404 hasopenings at formation 406. Portions of formation 414 may be optionallyfractured and/or perforated. As oil and gas is produced from formation406 it enters portions 414, and travels up well 412 to productionfacility 410. Gas and liquid may be separated, and gas may be sent togas processing 416, and liquid may be sent to liquid processing 418.Production facility 410 is able to produce and separate water floodingmixture, which may be produced and stored in production/storage 430.Water flooding mixture is pumped down well 432, to portions 434 offormation 406. Water flooding mixture traverses formation 406 to aid inthe production of oil and gas, and then the water flooding mixture, oiland gas may all be produced to well 412, to production facility 410.Water flooding mixture may then be recycled, for example by separatingthe water flooding mixture from the rest of the production stream, thenre-injecting the formulation into well 432.

In some embodiments, a quantity of water flooding mixture or waterflooding mixture mixed with other components may be injected into well432, followed by another component to force water flooding mixture orwater flooding mixture mixed with other components across formation 406,for example a liquid, such as water in gas or liquid form; water mixedwith one or more salts, polymers, and/or surfactants; or a gas, such asair; carbon dioxide; other gases; other liquids; and/or mixturesthereof.

In some embodiments, well 412 which is producing oil and gas isrepresentative of a well in well group 202, and well 432 which is beingused to inject water flooding mixture is representative of a well inwell group 204.

In some embodiments, well 412 which is producing oil and gas isrepresentative of a well in well group 204, and well 432 which is beingused to inject water flooding mixture is representative of a well inwell group 202.

FIG. 4:

Referring now to FIG. 4, in some embodiments of the invention, system500 is illustrated. System 500 includes production well 501 whichproduces a mixture of oil, water, gas, and a enhanced oil recoverysolvent such as dimethyl ether (DME). The mixture is sent to gas liquidseparator 502. A gas-DME mixture is taken off the top of separator 502and sent to absorption tower 506. Oil—DME and water—DME mixtures aresent to flash vessel 504 which operates at a lower pressure thanseparator 502.

The lower pressure in flash vessel 504 serves to boil off an additionalgas—DME mixture which is also sent to absorption tower 506. Flash vessel504 also separates oil for export which may be sent to a steam stripper516, and a water—DME mixture which is sent to stripper 508.

In absorption tower 506, the gas—DME mixtures from separator 502 andflash vessel 504 are contacted with fresh water at an elevated pressuresuch that a portion of the DME is transferred from the gas mixture andabsorbed into the fresh water. The water—

DME mixture may then be sent to injector well 510 for injection into asubsurface formation for enhanced oil recovery. Alternatively, thewater-DME mixture may be sent to a water-DME storage tank (not shown)for storage and subsequently sent to injector well 510 for injectioninto a subsurface formation for enhanced oil recovery. The lean gas maythen optionally be sent to turbo expander 512, and then onto stripper508. A portion of the lean gas may be exported and/or used foradditional DME production.

In the stripper 508, the lean gas is contacted with the water DMEmixture from flash vessel 504. Stripper 508 operates at a low pressureand optionally at a high temperature. The low pressure and optionallyhigher temperature of stripper 508 serves to raise the vapor pressure ofthe DME which is separated from the water-DME mixture and mixes with thelean gas to create a gas-DME mixture which is sent to absorption tower506. The water from stripper 508 may optionally be sent to polisher 514to remove additional DME and then be disposed of, for example byinjecting into a subsurface formation.

In some embodiments, the stripper 508 operates at a pressure from vacuum(0.05 bars) up to 10 bars, for example from about 0.1 to about 5 bars,or from about 0.25 to about 2.5 bars, or from about 0.5 to about 1.5bars.

In some embodiments, the stripper 508 operates at a temperature fromabout 25 to about 100° C., for example from about 30 to about 90° C., orfrom about 50 to about 75° C. In some embodiments, the stripper 508operates at a lower pressure than absorption tower 506.

In some embodiments, the stripper 508 operates at a higher temperaturethan absorption tower 506.

In some embodiments, the absorption tower 506 operates at a pressurefrom 5 bars up to 100 bars, for example from about 10 to about 75 bars,or from about 15 to about 50 bars, or from about 20 to about 30 bars.

In some embodiments, the absorption tower 506 operates at a temperaturefrom about 0 to about 50° C., for example from about 10 to about 45° C.,or from about 20 to about 40° C.

In some embodiments, fresh water fed to absorption tower 506 has a molarDME content of less than about 5%, for example less than about 3%, lessthan about 1%, or less than about 0.5%.

In some embodiments, water-DME mixture fed to stripper 508 has a molarDME content of greater than about 5%, for example greater than about7.5%, greater than about 10%, up to about 30%, or up to about 25%.

In some embodiments, gas-DME mixture fed to absorption tower 506 has amolar DME content of greater than about 5%, for example greater thanabout 7.5%, greater than about 10%, up to about 30%, or up to about 25%.

In some embodiments, gas fed to stripper 508 and/or gas for export has amolar DME content of less than about 5%, for example less than about 3%,less than about 1%, or less than about 0.5%.

In some embodiments, water for disposal from stripper 508 has a molarDME content of less than about 5%, for example less than about 3%, lessthan about 1%, or less than about 0.5%.

In some embodiments, although DME is described above in thespecification other solvent or water additives instead of or in additionto DME can also be used.

In some embodiments, oil and/or gas produced may be transported to arefinery and/or a treatment facility. The oil and/or gas may beprocessed to produced to produce commercial products such astransportation fuels such as gasoline and diesel, heating fuel,lubricants, chemicals, and/or polymers. Processing may includedistilling and/or fractionally distilling the oil to produce one or moredistillate fractions. In some embodiments, the oil and/or gas, and/orthe one or more distillate fractions may be subjected to a process ofone or more of the following: catalytic cracking, hydrocracking,hydrotreating, coking, thermal cracking, distilling, reforming,polymerization, isomerization, alkylation, blending, and dewaxing.

Waterflooding Mixture

In some embodiments, oil and gas may be recovered from a formation witha waterflooding mixture.

In some embodiments, the waterflooding mixture may include from about50% to about 99% water, for example from about 60% to about 98%, fromabout 70% to about 97%, from about 80% to about 96%, or from about 90%to about 95%.

The selection of water used in the waterflooding mixture is notcritical. Suitable water to be used in the mixture could be salt wateror fresh water, for example water from a body of water off such as asea, an ocean, a lake, or a river, from a water well, connate waterproduced from a subsurface formation, processed water from a city watersupply, gray water from a city sewage treatment plant, or another watersupply. In some embodiments, water used in the waterflooding mixture maybe subjected to one or more processing steps, such as those disclosed inUnited States Patent Application Publication Number US 2009/0308609, forexample, if water with a high salinity content will be used.

The waterflooding mixture may include one or more additives, such as asolvent, to increase its effectiveness, for example by boosting the oilrecovery factor, by swelling the oil, by lowering the viscosity of theoil, by increasing the mobility of the oil, and/or by increasing thesubsurface pressure in the formation.

In some embodiments, the waterflooding mixture may include from about 1%to about 50% additives, for example from about 2% to about 40%, fromabout 3% to about 30%, from about 4% to about 20%, or from about 5% toabout 10%.

Suitable additives to be used with the waterflooding mixture includechemicals having a molar solubility in water of at least about 1%, forexample at least about 2% or at least about 3%, up too fully misciblewith water, and having an octanol—water partition coefficient of atleast about 1, for example greater than about 1.3, greater than about 2,or greater than about 3.

In some embodiments, suitable waterflooding mixture additives aredisclosed in co-pending U.S. Provisional Patent Application 61/332,085.

In some embodiments, suitable waterflooding mixture additives includealcohols, amines, pyridines, ethers, carboxylic acids, aldehydes,ketones, phosphates, quinones, and mixtures thereof, where the chemicalhas a molar solubility in water of at least about 1% and anoctanol—water partition coefficient of at least about 1.

In some embodiments, suitable waterflooding mixture additives includeethers such as dimethyl ether, diethyl ether, and methyl-ethyl ether.

There are a number of chemicals that have a high solubility in water,which are in fact fully miscible in water, but which would not besuitable as a waterflooding mixture additive because of their very lowpartitioning coefficient. In operation, it would be easy to mix thesechemicals with water and inject them into a subsurface formation, but anegligible amount of the chemical would then be transferred to the crudeoil. In practice, one of these chemicals with a high solubility and alow partitioning coefficient would barely boost the recovery factor ascompared to a waterflood by itself.

There are also a number of chemicals that have a high partitioningcoefficient, but which would not be suitable as a waterflooding mixtureadditive because of their very low solubility in water. In operation,only a very small amount of these chemicals could be mixed with waterand injected into a subsurface formation, so that only a negligibleamount of the chemical would be transferred to the crude oil. In orderto achieve a large amount of the chemical been transferred to the crudeoil, a huge volume of water would have to be injected. In practice, oneof these chemicals with a low solubility and a high partitioningcoefficient would barely boost the recovery factor as compared to awaterflood by itself.

Immiscible Enhanced Oil Recovery Agents:

In some embodiments, suitable immiscible enhanced oil recovery agentsinclude liquids or gases, such as water in gas or liquid form, air,nitrogen, mixtures of two or more of the preceding, or other immiscibleenhanced oil recovery agents as are known in the art. In someembodiments, suitable immiscible enhanced oil recovery agents are notfirst contact miscible or multiple contact miscible with oil in theformation.

In some embodiments, a suitable immiscible enhanced oil recovery agentincludes water. The selection of water used as the immiscible agent isnot critical. Suitable water to be used could be salt water or freshwater, for example water from a body of water off such as a sea, anocean, a lake, or a river, from a water well, connate water producedfrom a subsurface formation, processed water from a city water supply,gray water from a city sewage treatment plant, or another water supply.In some embodiments, water used as the immiscible agent may be subjectedto one or more processing steps, such as those disclosed in UnitedStates Patent Application Publication Number US 2009/0308609, forexample, if water with a high salinity content will be used.

In some embodiments, immiscible agents and/or water flooding mixturesinjected into the formation may be recovered from the produced oil andgas and re-injected into the formation.

In one embodiment, after the injection of the water flooding mixture isstopped, there is a quantity of oil in the formation which has absorbeda quantity of waterflooding mixture additives. The oil is immobile andcan not be recovered. In order to recover the waterflooding mixtureadditives, a quantity of water without any additives may be injectedinto the formation and exposed to the oil, which water will absorb theadditives, and then the water additive mixture will be produced to thesurface.

In some embodiments, oil as present in the formation prior to theinjection of any enhanced oil recovery agents has a viscosity of atleast about 0.01 centipoise, or at least about 0.1 centipoise, or atleast about 0.5 centipoise, or at least about 1 centipoise, or at leastabout 2 centipoise, or at least about 5 centipoise. In some embodiments,oil as present in the formation prior to the injection of any enhancedoil recovery agents has a viscosity of up to about 500 centipoise, or upto about 100 centipoise, or up to about 50 centipoise, or up to about 25centipoise.

Surface Processes:

In some embodiments, oil and/or gas may be recovered from a formationwith a waterflooding mixture. In order to separate the productionfluids, the liquids may be separated from the gases, for example usinggravity based and/or centrifugal separators as are known in the art.Then, the liquids may be separated, where the water may be separatedfrom the oil for example using gravity based and/or centrifugalseparators as are known in the art. The gas, the oil and the water maystill contain some waterflooding mixture additives. The oil may undergoa distillation process to flash the waterflooding mixture additives andlight hydrocarbons. This mixture of the waterflooding mixture additivesand light hydrocarbons may be added to the gas phase. The gas phase willthen be exposed to the water which will preferentially pull out thewaterflooding mixture additives and leave behind the light hydrocarbons.At the end of the process, most of the waterflooding mixture additiveswill have been removed from the oil and gas so that they can beexported, while the water mixed with the waterflooding mixture additiveswill be ready to be recycled into the same field or stored and used inanother field.

Illustrative Embodiments:

In one embodiment of the invention, there is disclosed a system forproducing oil and gas from an underground formation comprising a wellabove the formation; a mechanism to inject an enhanced oil recoveryformulation into the formation, the enhanced oil recovery formulationcomprising water and a solvent; a mechanism to produce the water,solvent, oil, and gas from the formation; a separator to separate theoil, water, and a first portion of the solvent from the gas and a secondportion of the solvent; and an absorption tower to expose the gas andthe second portion of the solvent to water to remove the second portionof the solvent from the gas. In some embodiments, the system alsoincludes a second well a distance from the first well, wherein themechanism to produce the water, solvent, oil, and gas from the formationis located at the second well. In some embodiments, the system alsoincludes a stripper to expose the water and a first portion of thesolvent to a gas to remove the first portion of the solvent from thewater. In some embodiments, the system also includes a first conduit topass the gas from the absorption tower to the stripper. In someembodiments, the system also includes a turbo expander in the firstconduit to lower a pressure of the gas and to extract energy from thegas. In some embodiments, the system also includes a second conduit topass the water from the stripper to the absorption tower. In someembodiments, the solvent comprises a chemical having a solubility inwater of at least 1% (at atmospheric conditions) and a octanol-waterpartitioning coefficient of at least 1 (at atmospheric conditions). Insome embodiments, the well comprises an array of wells from 5 to 500wells. In some embodiments, the mechanism to produce oil and gas fromthe formation is located at the well. In some embodiments, the solventcomprises a chemical having a solubility in water of at least 2% at apressure of 50 bars and a temperature of 25 degrees centigrade. In someembodiments, the solvent comprises a chemical having a crude oil—waterpartitioning coefficient of at least 2 at a pressure of 50 bars and atemperature of 25 degrees centigrade.

In one embodiment of the invention, there is disclosed a method forproducing oil and gas comprising injecting water and an solvent into aformation; producing a mixture comprising water, the solvent, oil andgas from the formation; separating the mixture into a first streamcomprising oil, water, and a first portion of the solvent, and a secondstream comprising gas and a second portion of the solvent. In someembodiments, the method also includes exposing the second stream towater to remove the second portion of the solvent from the gas. In someembodiments, the method also includes separating oil from the firststream to form a third stream. In some embodiments, the method alsoincludes exposing the third stream to gas to remove the first portion ofthe solvent from the water. In some embodiments, the method alsoincludes converting at least a portion of the recovered oil or gas intoa material selected from the group consisting of transportation fuelssuch as gasoline and diesel, heating fuel, lubricants, chemicals, and/orpolymers. In some embodiments, the water further comprises a watersoluble polymer adapted to increase a viscosity of the mixture. In someembodiments, the method also includes reducing a bubble point of the oilin the formation with the solvent. In some embodiments, the method alsoincludes increasing a swelling factor of the oil in the formation withthe solvent. In some embodiments, the method also includes reducing aviscosity of the oil in the formation with the solvent. In someembodiments, the water and the solvent is injected into a reservoirhaving a reservoir temperature of at least 100 degrees centigrade, forexample at least 250 degrees centigrade, measured prior to wheninjection begins. In some embodiments, the underground formationcomprises a permeability from 0.0001 to 15 Darcies, for example apermeability from 0.001 to 1 Darcy.

Those of skill in the art will appreciate that many modifications andvariations are possible in terms of the disclosed embodiments of theinvention, configurations, materials and methods without departing fromtheir spirit and scope. Accordingly, the scope of the claims appendedhereafter and their functional equivalents should not be limited byparticular embodiments described and illustrated herein, as these aremerely exemplary in nature.

What is claimed is:
 1. A method for producing oil, comprising: injectingwater and a solvent into a formation; producing a mixture comprisingwater, solvent, oil, and gas from the formation; separating the mixtureinto a first stream comprising oil, water, and a first portion of thesolvent, and a second stream comprising gas and a second portion of thesolvent, and exposing the second stream to water to remove the secondportion of the solvent from the gas.
 2. The method of claim 1, furthercomprising separating oil from the first stream to form a third streamcomprising water and the first portion of the solvent.
 3. The method ofclaim 2, further comprising exposing the third stream to gas to removethe first portion of the solvent from the water.
 4. The method of claim1, further comprising converting at least a portion of the produced oilor produced gas into a material selected from the group consisting oftransportation fuels, heating fuels, lubricants, chemicals, andpolymers.
 5. The method of claim 1, wherein the water injected into theformation further comprises a water soluble polymer adapted to increasea viscosity of the mixture.
 6. The method of claim 1, further comprisingreducing the bubble point of oil in the formation with the solvent. 7.The method of claim 1, further comprising increasing the swelling factorof oil in the formation with the solvent.
 8. The method of claim 1,further comprising reducing the viscosity of oil in the formation withthe solvent.
 9. The method of claim 1 wherein the formation is anunderground formation.
 10. The method of claim 10, wherein theunderground formation has a temperature of at least 100 degreescentigrade as measured prior injection of water and solvent into theformation.
 11. The method of claim 10, wherein the underground formationhas a permeability from 0.0001 to 15 Darcies.